Method of Enhancing the Effectiveness of a Cyclic Solvent Injection Process to Recover Hydrocarbons

ABSTRACT

Described is a method of operating a cyclic solvent-dominated recovery process (CSDRP) for recovering viscous oil from a subterranean reservoir of the viscous oil to enhance recovery effectiveness. The cyclic solvent process involves using an injection well to inject a viscosity-reducing solvent into a subterranean viscous oil reservoir. Reduced viscosity oil is produced to the surface using the same well used to inject solvent. The process of alternately injecting solvent and producing a solvent/viscous oil blend through the same wellbore continues in a series of cycles until additional cycles are no longer economical. Conventionally, the solvent composition remains constant over time within each injection cycle and among cycles. In the present method, by contrast, the solvent composition is varied over time thereby providing operational benefits as described herein.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of Canadian patent application number 2,738,364 filed on Apr. 27, 2011 entitled METHOD OF ENHANCING THE EFFECTIVENESS OF A CYCLIC SOLVENT INJECTION PROCESS TO RECOVER HYDROCARBONS, the entirety of which is incorporated herein.

FIELD

The present disclosure relates generally to the recovery of in-situ hydrocarbons. More particularly, the present disclosure relates to the use of a cyclic solvent-dominated recovery process (CSDRP) to recover in-situ hydrocarbons including bitumen.

BACKGROUND

At the present time, solvent-dominated recovery processes (SDRPs) are not commonly used as commercial recovery processes to produce highly viscous oil. Highly viscous oils are produced primarily using thermal methods in which heat, typically in the form of steam, is added to the reservoir. Cyclic solvent-dominated recovery processes (CSDRPs) are a subset of SDRPs. A CSDRP is typically, but not necessarily, a non-thermal recovery method that uses a solvent to mobilize viscous oil by cycles of injection and production. Solvent-dominated means that the injectant comprises greater than 50% by mass of solvent or that greater than 50% of the produced oil's viscosity reduction is obtained by dilution with solvent rather than by thermal means. One possible laboratory method for roughly comparing the relative contribution of heat and dilution to the viscosity reduction obtained in a proposed oil recovery process is to compare the viscosity obtained by diluting an oil sample with a solvent to the viscosity reduction obtained by heating the sample.

In a CSDRP, a viscosity-reducing solvent is injected through a well into a subterranean viscous-oil reservoir, causing the pressure to increase. Next, the pressure is lowered and reduced-viscosity oil is produced to the surface through the same well through which the solvent was injected. Multiple cycles of injection and production are used.

CSDRPs may be particularly attractive for thinner or lower-oil-saturation reservoirs. In such reservoirs, thermal methods utilizing heat to reduce viscous oil viscosity may be inefficient due to excessive heat loss to the overburden and/or underburden and/or reservoir with low oil content.

References describing specific CSDRPs include: Canadian Patent No. 2,349,234 (Lim et al.); Lim et al., “Three-dimensional Scaled Physical Modeling of Solvent Vapour Extraction of Cold Lake Bitumen”, The Journal of Canadian Petroleum Technology, 35(4), pp. 32-40, April 1996; Lim et al., “Cyclic Stimulation of Cold Lake Oil Sand with Supercritical Ethane”, SPE Paper 30298, 1995; U.S. Pat. No. 3,954,141 (Allen et al.); and Feali et al., “Feasibility Study of the Cyclic VAPEX Process for Low Permeable Carbonate Systems”, International Petroleum Technology Conference Paper 12833, 2008.

The family of processes within the Lim et al. references describes embodiments of a particular SDRP that is also a cyclic solvent-dominated recovery process (CSDRP). These processes relate to the recovery of heavy oil and bitumen from subterranean reservoirs using cyclic injection of a solvent in the liquid state which vaporizes upon production. The family of processes within the Lim et al. references may be referred to as CSP™ processes.

With reference to FIG. 1, which is a simplified diagram based on Canadian Patent No. 2,349,234 (Lim et al.), one CSP™ process embodiment is described as a single well method for cyclic solvent stimulation, the single well preferably having a horizontal wellbore portion and a perforated liner section. A vertical wellbore (1) driven through overburden (2) into reservoir (3) is connected to a horizontal wellbore portion (4). The horizontal wellbore portion (4) comprises a perforated liner section (5) and an inner bore (6). The horizontal wellbore portion comprises a downhole pump (7). In operation, solvent or viscosified solvent is driven down and diverted through the perforated liner section (5) where it percolates into reservoir (3) and penetrates reservoir material to yield a reservoir penetration zone (8). Oil dissolved in the solvent or viscosified solvent flows into the well and is pumped by downhole pump through an inner bore (6) through a motor at the wellhead (9) to a production tank (10) where oil and solvent are separated and the solvent is recycled.

SUMMARY

Generally, the present disclosure relates to a method of enhancing the effectiveness of a cyclic solvent-dominated recovery process (CSDRP) for recovering viscous oil from a subterranean reservoir of the viscous oil. The cyclic solvent process involves using an injection well to inject a viscosity-reducing solvent into a subterranean viscous oil reservoir. Reduced viscosity oil is produced to the surface using the same well used to inject solvent. The process of alternately injecting solvent and producing a solvent/viscous oil blend through the same wellbore continues in a series of cycles until additional cycles are no longer economical. Conventionally, the solvent composition remains constant over time within each injection cycle and among cycles. In the present method, by contrast, the solvent composition is varied over time thereby providing operational benefits as described below.

In a first aspect, there is provided a method of enhancing the effectiveness of a cyclic solvent injection and production process to aid recovery of in-situ hydrocarbons from an underground reservoir, the method comprising: (a) injecting a volume of fluid comprising greater than 50 mass % of a viscosity-reducing solvent into an injection well completed in the reservoir; (b) halting injection into the injection well and subsequently producing at least a fraction of the injected fluid and the in-situ hydrocarbons from the reservoir through a production well; (c) halting production through the production well; and (d) subsequently repeating the cycle of steps (a) to (c); wherein a 50 mass % vaporization temperature at 1 atm of a total composition of solvent injected over a first period, is at least 10° C. higher than a 50 mass % vaporization temperature at 1 atm of a total composition of solvent injected over a subsequent period.

Other aspects and features of the present disclosure will become apparent to those ordinarily skilled in the art upon review of the following description of specific embodiments of the invention in conjunction with the accompanying figures.

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments of the present invention will now be described, by way of example only, with reference to the attached Figures, wherein:

FIG. 1 is a schematic of a CSP™ process in accordance Canadian Patent No. 2,349,234 (Lim et al.).

FIG. 2 shows a solvent composition variation scheme over early, mid, and late cycles, starting at a high concentration of a heavy hydrocarbon or organic solvent and transitioning to a high concentration of a light vaporizable hydrocarbon solvent, according to a disclosed embodiment.

FIG. 3 shows an alternative to FIG. 2 with solvent composition varying from cycle to cycle, starting at pure heavy solvent and transitioning to pure light vaporizable solvent, according to a disclosed embodiment.

FIG. 4 is a schematic of the anticipated solvent fingering in a given cycle for equivalent total solvent volumes injected of a pure low viscosity, light solvent vs. that of a high viscosity, heavy solvent followed by a low viscosity, light solvent.

FIG. 5 is a flow chart for determining what solvent composition should be injected throughout a given cycle with decision points related to injection pressure, injection duration, and injection volume, according to a disclosed embodiment.

FIG. 6 is flow chart for determining what solvent composition should be injected for a given cycle with decision points related to cycle number according to a disclosed embodiment.

FIG. 7 is a graph of the solvent storage ratio (the volumetric ratio of solvent remaining in the reservoir to oil produced) as a function of time over several cycles when operating with a single component fully miscible solvent above and below the solvent vaporization pressure.

FIG. 8 is a table with the approximate solubilities of some hydrocarbon and non-hydrocarbon solvents in Cold Lake bitumen and approximate fluid characteristics at 13° C.

FIG. 9 is a table of the approximate boiling point temperatures of some of the solvents of interest for this process at 1 atm.

FIG. 10 is a graph illustrating density of the solvent-bitumen blend as a function of volume % of total solvent blended into Cold Lake bitumen for Sample 1.

FIG. 11 is a graph illustrating density of the solvent-bitumen blend as a function of volume % of total solvent blended into Cold Lake bitumen for Sample 2.

DETAILED DESCRIPTION

In-situ is a Latin phrase for “in the place” and, in the context of hydrocarbon recovery, refers generally to a subsurface hydrocarbon-bearing reservoir. For example, in-situ temperature means the temperature within the reservoir. In another usage, an in-situ oil recovery technique is one that recovers oil from a reservoir within the earth.

The term “viscous oil” as used herein means a hydrocarbon, or mixture of hydrocarbons, that occurs naturally and that has a viscosity of at least 10 cP (centipoise) at initial reservoir conditions. Viscous oil includes oils generally defined as “heavy oil” or “bitumen”. Bitumen is classified as extra heavy oil, with an API gravity of about 10° or less, referring to its gravity as measured in degrees on the American Petroleum Institute (API) Scale. Heavy oil has API gravity in the range of about 22.3° to about 10°. The terms viscous oil, heavy oil, and bitumen are used interchangeably herein since they may be extracted using similar processes. The terms viscous oil, heavy oil, and bitumen are also all considered in-situ hydrocarbons as used herein.

The term “formation” as used herein refers to a subterranean porous media. The terms “reservoir” and “formation” may be used interchangeably.

The term “cycle” as used herein refers to the combination of an injection period and the next subsequent production period. An injection or production period may be continuous or may comprise one or more idle times.

The expression “a 50 mass % vaporization temperature at 1 atm of a total composition of solvent” refers to the minimum temperature at which 50 mass % of the composition of the solvent is vapor at 1 atm as determined by a single-stage equilibrium flash. For many pure components at 1 atm it is well known that this temperature is the boiling point temperature. A table of boiling point temperatures is provided in FIG. 9. For CO₂, however, at 1 atm, the minimum temperature at which 50 mass % of the composition of the total solvent injected is vapor is the sublimation temperature.

The terms “heavier”, “heavier solvent”, and “heavy solvent” may be used interchangeably and will be used to describe a fluid which has a higher 50 mass % vaporization temperature at 1 atm, which generally will be correlated to the molecular weight, particularly for similar fluids, but is not necessarily always the case as shown in FIG. 9. Similarly, the terms “lighter”, “lighter solvent”, and “light solvent” may be used interchangeably and will be used to denote a fluid which has a lower 50 mass % vaporization temperature at 1 atm.

Generally, a fluid with a higher 50 mass % vaporization temperature may also have a lower asphaltene precipitation rate and a higher solubility (more miscible) when mixed with in-situ heavy oil.

In some cases, a fluid with a higher 50 mass % vaporization temperature may also have a higher aromatic content.

Before discussing, under section (A) below, varying the solvent composition over time, a more general embodiment of CSDRP will be described.

Another description of a CSDRP is provided in Canadian Patent Application No. 2,688,392 to Lebel et al.

During a CSDRP, a reservoir accommodates the injected solvent and non-solvent fluid by compressing the pore fluids and, perhaps dilating the reservoir pore space when sufficient injection pressure is applied. Pore dilation is a particularly effective mechanism for permitting solvent to enter into reservoirs filled with viscous oils when the reservoir comprises largely unconsolidated sand grains. Injected solvent fingers into the oil sands and mixes with the viscous oil to yield a reduced viscosity mixture with significantly higher mobility than the native viscous oil. Without intending to be bound by theory, the primary mixing mechanism is thought to be dispersive mixing, not diffusion. Preferably, injected fluid in each cycle replaces the volume of previously recovered fluid and then adds sufficient additional fluid to contact previously uncontacted viscous oil. Preferably, the injected fluid comprises greater than 50% by mass of solvent.

On production, the pressure is reduced and the solvent(s), non-solvent injectant, and viscous oil flow back to the same well and are produced to the surface. As the pressure in the reservoir falls, the produced fluid rate declines with time. Production of the solvent/viscous oil mixture and other injectants may be governed by any of the following mechanisms: gas drive via solvent vaporization and native gas exsolution, compaction drive as the reservoir dilation relaxes, fluid expansion, and gravity-driven flow. The relative importance of the mechanisms not only depends on static properties such as solvent properties, native GOR (Gas to Oil Ratio), fluid and rock compressibility characteristics, and reservoir depth, but also on operational practices such as solvent injection volume, producing pressure, and viscous oil recovery to-date, among other factors.

During an injection/production cycle, the volume of produced oil should be above a minimum threshold to economically justify continuing operations. In addition to an acceptably high production rate, the oil should also be recovered in an efficient manner. One measure of the efficiency of a CSDRP is the ratio of produced oil volume to injected solvent volume over a time interval, called the OISR (produced Oil to Injected Solvent Ratio), with a higher OISR being desirable. Typically, the time interval is one complete injection/production cycle. Alternatively, the time interval may be from the beginning of first injection to the present or some other time interval. When the OISR falls below a certain threshold, further solvent injection may become uneconomic, indicating that the solvent should be injected into a different well operating at a higher OISR. The exact OISR threshold depends on the relative price of viscous oil and solvent, among other factors. If either the oil production rate or the OISR becomes too low, the CSDRP may be discontinued.

The OISR is one measure of solvent efficiency in recovering heavy oil. Those skilled in the art will recognize that there are a multitude of other measures of solvent efficiency, such as the inverse of the OISR, or measures of solvent efficiency on a temporal basis that is different from the temporal basis discussed in this disclosure. To maximize the economic return of a producing oil well, it is desirable to maintain an economic oil production rate and an economic OISR as long as possible and then recover as much of the solvent as possible.

The Solvent Storage Ratio (SSR) is also a common measure of solvent efficiency. The SSR is a measure of the solvent fraction unrecovered from the reservoir divided by the in-situ oil produced from the reservoir. SSR is more explicitly defined as the ratio of the cumulative solvent injected into the reservoir minus the cumulative solvent produced from the reservoir to the cumulative in-situ oil produced from the reservoir. A lower SSR indicates lower solvent losses per volume of in-situ oil recovered, and thus, better total solvent recovery per volume of in-situ oil produced. Therefore, a lower SSR would indicate an improvement in solvent efficiency.

Even if oil rates are high and the solvent use is efficient, it is also important to recover as much of the injected solvent as possible, as the solvent has an economic value. Depending on the physical properties of the injected solvent, the remaining solvent may be recovered by producing to a low pressure to vaporize the solvent in the reservoir to aid its recovery. In addition, rather than abandoning the well, another recovery process may be initiated.

SSR is one measure of injected solvent recovery. Those skilled in the art will recognize that there are many other measures of solvent recovery, such as the percentage loss, volume of unrecovered solvent per volume of recovered oil, or its inverse, the volume of produced oil to volume of lost solvent ratio (OLSR).

As used herein, “improving solvent efficiency” means (a) improving the OISR, or (b) improving the SSR, or (c) improving both the OISR and the SSR.

Injection of a solvent-containing fluid into a well is the first step of a CSDRP and the rates and volumes of injected fluid are an integral part of any CSDRP. Note that, unlike thermal recovery methods where minimum injection rates are often specified to minimize wellbore heat loss, CSDRP injection rates may have considerable flexibility to either reduce and/or increase injection rate depending on specific reservoir conditions, in particular the level of reservoir depletion. Rate flexibility allows the operator to optimize the distribution of solvent among wells in order to balance field injection/production volumes and surface gathering system constraints. Three non-limiting options for determining the volume of solvent-containing injectant to inject are: a purely volume-based approach, a hybrid volume and pressure approach, and a purely pressure-based approach. Each of these three approaches are described below and referred to as A1, A2, and A3.

A1: Volume-Based Determination of Injection Volume

One method of managing fluid injection in a CSDRP is for the volume injected during a cycle to equal the net reservoir voidage resulting from previous injection and production cycles plus an additional volume, for example approximately 2-15%, or approximately 3-8% of the pore volume (PV) of the reservoir volume associated with the well pattern. In mathematical terms, the volume may be represented by:

V _(INJECTANT) =V _(VOIDAGE) +V _(ADDITIONAL).

One way to approximate the net in-situ volume of fluids produced is to determine the total volume of non-solvent liquid hydrocarbon fractions and aqueous fractions produced minus the net injectant fractions produced. For example, in the case where 100% of the injectant is solvent and the reservoir contains only oil and water, an equation that represents the net in-situ volume of fluids produced is,

V _(VOIDAGE) =V _(OIL) ^(PRODUCED) +V _(WATER) ^(PRODUCED)−(V _(SOLVENT) ^(INJECTED) −V _(SOLVENT) ^(PRODUCED)).

Estimates of the PV are the reservoir volume inside a unit cell of a repeating well pattern or the reservoir volume inside a minimum convex perimeter defined around a set of wells. Fluid volume may be calculated at in-situ conditions, which take into account reservoir temperatures and pressures. If the application is for a single well, the “pore volume of the reservoir” is defined by an inferred drainage radius region around the well which is approximately equal to the distance that solvent fingers are expected to travel during the injection cycle (for example, about 30-200 m). Such a distance may be estimated by reservoir surveillance activities, reservoir simulation or reference to prior field trials. In this approach, the pore volume may be estimated by direct calculation using the estimated distance, and injection ceased when the associated injection volume (2-15% PV) has been reached.

Sometimes, it is challenging to define the “pore volume accessible to the well” because of geological heterogeneity or uncertainties in the distance the solvent fingers are expected to travel. The relative ease of pressure measurement and generally higher accuracy versus volumetric measurement may lead to a preference for pressure or hybrid pressure-volume methods.

A2: Volume-Pressure Hybrid Determination of Injection Volume

Rather than estimating the net reservoir voidage resulting from previous injection and production cycles, it may be more practical to establish a threshold pressure which must be obtained before injecting a predetermined volume, for example also equal to approximately 2-15%, or approximately 3-8%, of the pore volume.

A3: Pressure-Based Determination of Injection Volume

An alternative to a volume-based scheme is one based on pressure measurements. In this approach, the solvent injection continues until an approximately predetermined time after the injection pressure during a cycle first passes from less than to greater than a designated threshold injection pressure. In some cases, it may be desirable to continue injection past the threshold pressure for only a minimal amount of time. In other cases, it may be desirable to stop injection once the threshold pressure is met.

In one embodiment, in both the volume-pressure hybrid and pressure-only approaches, the designated threshold injection pressure is a pressure close to but below fracture pressure, for example above 90% of fracture pressure, or above 80% of fracture pressure, or above 95% of fracture pressure. In one embodiment, the threshold injection pressure is a pressure within 1 MPa of, and below, the fracture pressure. As used herein, “fracture pressure” is the pressure at which injection fluids will cause the formation to fracture. As used herein, “dilation pressure” refers to the onset of in-elastic dilation, the yielding of the geo-materials, or the onset of non-linear elastic deformation. As used herein, “geomechanical formation dilation” means the tendency of a geomechanical formation to dilate as the pore pressure is raised towards the formation minimum in-situ stress, typically by injecting a liquid or a gas. As is sometimes the case for unconsolidated sands, there is a particular pressure at which dilation, the change of pore volume (porosity) with change in pressure, markedly increases.

Solvent Composition

The solvent may be a hydrocarbon, mixture of hydrocarbons, or organic compound comprising methane, ethane, propane, butane, C₃+ hydrocarbons, ketones, diesel, viscous oil, bitumen, diluent, synthetic crude oils, heavy vacuum gas oils, alchohols, or CO₂. Non-solvent co-injectants may include steam, hot water, non-condensable gas, or hydrate inhibitors. Viscosifiers may be useful in adjusting solvent viscosity to reach desired injection pressures at available pump rates and may include diesel, viscous oil, bitumen, or diluent. The injection of a solvent slurry may provide further means to reach the desired injection pressure by viscosifying the injectant, reducing the effective permeability of the formation to the injectant, or a combination thereof. The solids suspended in the solvent slurry could comprise biodegradable solid particles, salt, water soluble solid particles, or solvent soluble solid particles. Viscosifiers may be in the liquid, gas, or solid phases. Preferably, viscosifiers would be soluble in either one of the components of the injected solvent and water and transition to the liquid phase in the reservoir before or during production, reducing their ability to increase the viscosity of the produced fluids and/or decrease the effective permeability of the formation to the produced fluids. In addition to providing a means to reach the desired injection pressure, the viscosifiers may also reduce the average distance solvent travels from the well during an injection period. Viscosifiers may also act as solvents and therefore may provide flow assurance near the wellbore and in the surface facilities in the event of asphaltene precipitation or solvent vaporization during shut-in periods.

In one embodiment, the solvent comprises greater than 50% C₂-C₅ hydrocarbons on a mass basis. In one embodiment, the solvent is primarily propane, optionally with diluent when it is desirable to adjust the properties of the injectant to improve performance. Alternatively, wells may be subjected to compositions other than these main solvents to improve well pattern performance, for example CO₂ flooding of a mature operation.

Phase of Injected Solvent

In one embodiment, the solvent is injected into the well at a pressure in the underground reservoir above a liquid/vapor phase change pressure (also known as the bubble point pressure) such that at least 25 mass % of the solvent enters the reservoir in the liquid phase. Alternatively, at least 50, 70, or even 90 mass % of the solvent may enter the reservoir in the liquid phase. Injection as a liquid may be preferred for achieving high pressures because pore dilation at high pressures is thought to be a particularly effective mechanism for permitting solvent to enter into reservoirs filled with viscous oils when the reservoir comprises largely unconsolidated sand grains. Injection as a liquid also may allow higher overall injection rates than injection as a gas. Surface facilities for the injection of liquid solvent are significantly simplified with liquid injection versus gas injection.

In some embodiments, it may be desirable to inject a fraction of the injectant in the solid phase in order to mitigate adverse solvent fingering, increase injection pressure, or keep the average distance of the solvent closer to the wellbore than in the case of pure liquid phase injection. In one embodiment, less than 20 mass % of the injectant enters the reservoir in the solid phase. Alternatively, less than 10 mass % or less than 50 mass % of the injectant enters the reservoir in the solid phase. In one embodiment, once in the reservoir, the solid phase of the injectant would transition to a liquid phase before or during production to prevent or mitigate reservoir permeability reduction during production.

In an alternative embodiment, the solvent volume is injected into the well at rates and pressures such that immediately after completing injection into the injection well during an injection period in which at least 25 mass % of the injected solvent is in a liquid state in the underground reservoir. Injection of the injectant as a vapor may be preferred in order to enable more uniform solvent distribution along a horizontal well, particularly when variable injection rates are targeted. Vapor injection in a horizontal well may also facilitate an upsize in the port size of installed inflow control devices (ICDs) thereby minimizing the risk of plugging the ICDs. Injecting as a vapor may increase the ability to pressurize the reservoir to a desired pressure by lower effective permeability of an injected vapor in a formation comprising liquid viscous oil. In one embodiment, a non-condensable gas is injected to achieve a desired pressure, followed by injection of a solvent. Alternating periods of a primarily non-condensable gas with primarily solvent injection may provide a means of maintaining the desired injection pressure target. The primarily gas injection period may offset the pressure leak off observed during primarily solvent injection to reestablish the desired injection pressure. Furthermore this alternating strategy of gas to liquid solvent injection periods may result in non-condensable gas accumulations in the previously established solvent pathways. The accumulation of non-condensable gas may divert the subsequently injected solvent to bypassed viscous oil thereby increasing the mixing of solvent and oil in the producing well's drainage area. In another embodiment, an injectant in the vapor phase, such as CO₂ or natural gas, may be injected, followed by injection of a solvent. In another embodiment, depending on the pressure of the reservoir, it may be desirable to significantly heat the solvent in order to inject it as a vapor. Heating of injected vapor or liquid solvent may enhance production through mechanisms described by “Boberg and Lantz, “Calculation of the production of a thermally stimulated well”, JPT, pg. 1613-1623, December 1966. Towards the end of the injection period, a portion of the injected solvent, perhaps 25% or more, may become a liquid as pressure rises. After the targeted injection cycle volume of solvent is achieved, no special effort is made to maintain the injection pressure at the saturation conditions of the solvent, and liquefaction would occur through pressurization, not condensation. Downhole pressure gauges and/or reservoir simulation may be used to predict the phase of the solvent and other co-injectants at downhole conditions and in the reservoir. A reservoir simulation may be carried out using a reservoir simulator, a software program for mathematically modeling the phase and flow behavior of fluids in an underground reservoir. Those skilled in the art understand how to use a reservoir simulator to determine if 25% of the injectant would be in the liquid phase immediately after the completion of an injection period. Those skilled in the art may rely on measurements recorded using a downhole pressure gauge in order to increase the accuracy of a reservoir simulator. Alternatively, the downhole pressure gauge measurements may be used to directly make the determination without the use of reservoir simulation.

Although preferably CSDRP is predominantly a non-thermal process in that heat is not used principally to reduce the viscosity of the viscous oil, the use of heat is not excluded. Heating may be beneficial to improve performance by an improved process start-up and/or provide flow assurance during production. For injection start-up, low-level heating (for example, less than 100° C.) of the solvent prior to injection may be performed to prevent hydrate formation in tubulars and in the reservoir. Two non-exclusive scenarios of injecting a heated solvent are as follows. In one scenario, vapor solvent would be injected and would condense when it reaches the bitumen. In this case, the phase of injected solvent is used primarily to achieve uniform distribution in a horizontal well. In another scenario, a vapor solvent would be injected at up to 200° C. and would become a supercritical fluid at downhole operating pressure. In this case, the increased temperature of the injected solvent creates a larger region of heated reservoir that may optimize production by a larger effective well radius. Injected heat creates a uniform radial region of mobilized viscous oil to compliment a perhaps non-uniform region of mobilized viscous oil resulting from dispersive mixing of solvent injection.

(A) Varying the Solvent Composition Over Time

Previous descriptions of CSDRPs typically describe the solvent as a light, but condensable, hydrocarbon or mixture of hydrocarbons comprising ethane, propane, or butane. Light solvents, however, also have a low viscosity which can make it challenging to reach desired injection pressures. Heavier, more viscous, organic solvents may be added, according to embodiments described herein, to optimally adjust solvent viscosity to reach desired injection pressures at available pump rates. Therefore, it may be desired to inject a heavier hydrocarbon solvent or a heavier organic solvent during the early part of any injection cycle to achieve the desired injection pressure, which may then be maintained by injection of a lighter solvent such as a light alkane, potentially at lower rates. However, current methods do not teach injection of a solvent with composition varying throughout a cycle. Carbon dioxide or hydrocarbon mixtures including carbon dioxide may also be desirable to use as a solvent. The solvent may be heated prior to injection, primarily to prevent hydrate formation, or for the reasons described above.

During a CSDRP, a reservoir accommodates the injected solvent by compressing the pore fluids and, perhaps dilating pore space when sufficient injection pressure is applied. Pore dilation is a particularly effective mechanism for permitting solvent to enter into reservoirs filled with viscous oils when the reservoir is composed of largely unconsolidated sand grains. Injected solvent fingers into the oil sands and mixes with the bitumen to yield a reduced viscosity mixture with significantly higher mobility than the native bitumen. Fingering, rather than growth of a smooth solvent front, occurs due to the much lower viscosity of the solvent than the native oil. Such a condition leads to inherent flow instabilities called viscous fingering. Solvent miscibility (complete or partial) with the native oil and reservoir pore dilation may both act to control finger growth and in turn optimize contact with the bitumen. It is therefore desired in some cases to have a highly soluble solvent to permit efficient viscosity reduction of the bitumen and good utilization of solvent to mitigate adverse fingering. However, light hydrocarbon solvents can have low solubility in bitumen, which tends to favor injection of a heavier hydrocarbon solvent or heavier organic solvent, particularly early in the injection cycle for the aforementioned reasons for achieving a target injection pressure. It is also important when selecting a solvent to consider the impact of the solvent on the reservoir quality, particularly on the pore space and permeability of the formation. Lighter alkane solvents (ethane, propane, butane, etc.) also tend to precipitate asphaltenes, resulting in variable oil composition of the production product and in some cases may reduce the permeability of the formation. Heavier solvents tend not to result in asphaltene precipitation. Because lighter solvents may have a lower miscibility in native bitumen, they may cause the formation of multiple liquid phases in the reservoir, which can decrease the efficiency of the process. On the other hand, heavier solvents may have a higher miscibility in the native bitumen, mitigating the formation of multiple liquid hydrocarbon phases. However, lighter solvents are more easily recovered from the formation than are heavier solvents since the pressure is dropped below the vaporization temperature of the lighter solvent on production. By contrast, the efficient recovery of heavier solvents may be difficult because an appreciable volume of solvent may remain trapped in unrecovered bitumen or in the reservoir pore space. Leaving an appreciable volume of solvent in the reservoir can negatively impact process economics. Embodiments described herein may overcome this deficiency by injecting, during early cycles, it is desired to inject a larger fraction of heavier hydrocarbon or organic solvent to prevent (or mitigate) formation damage, particularly near wellbore. Preferably, injected solvent per cycle fills the void space left by previously recovered bitumen and then adds sufficient additional solvent to propagate solvent fingers into previously uncontacted bitumen, where it then mixes efficiently with high solubility, reducing the bitumen viscosity and resulting in minimal asphaltene precipitation. Therefore, it may be preferred that heavier solvents be used in early cycles or in the beginning of injection in a given cycle to prevent (or mitigate) asphaltene precipitation near wellbore and to ensure good utilization of solvent and good mixing while lighter solvents may be useable in later cycles or in the later portion of a given cycle to assist in efficient solvent recovery by the increased mobility of lighter solvents. In later cycles, asphaltene precipitation may be less of an issue with lighter solvents as more of the bitumen near wellbore has been contacted by heavy solvent and more of the uncontacted bitumen in the reservoir is far from the wellbore. Also, migrating from heavier solvent to lighter solvent can reduce the operating cost of the field application. As cycles mature an increased amount of injected solvent is required to fill reservoir voidage and contact bypassed bitumen. The cost of the increased solvent volume by cycle may be offset by utilizing typically lower cost lighter solvents. Varying the injected solvent composition within a well cycle can also increase the process efficiency. Particularly in a field application of primarily light solvent cycle injection it may be optimal to have a periodic flush during the production cycle with a heavier solvent to restore flow assurance by dissolving near-wellbore solid hydrocarbon build up (i.e. asphaltenes, wax, paraffins, etc.) in the wellbore and near-wellbore region. However, current processes do not teach varying injected solvent composition from cycle to cycle or within a cycle.

During production in a CDSRP, pressure is reduced and the mixture of solvents and bitumen flows back to the same horizontal well and is produced to surface. As the pressure in the reservoir falls, the produced fluid rate declines with time. The pressure at the end of a cycle's production phase is typically less than the solvent vapor pressure, but such low pressures may not be necessary, especially in early cycles. Production of the solvent/bitumen mixture is governed by the following mechanisms: gas drive via solvent vaporization and native gas exsolution, compaction drive as the dilation relaxes, fluid expansion, and gravity-driven flow. The relative importance of the mechanisms depends on static properties such as solvent properties, native GOR, fluid and rock compressibility characteristics, and reservoir depth, but also depends on operational practices such as solvent injection volume, producing pressure, and bitumen recovery to-date, among other factors. During production, it is desired that a large fraction of the injected solvent is utilized to reduce the bitumen viscosity and that a large fraction of the injected solvent is produced back, particularly in later cycles. In order to achieve high solvent recoveries in late cycles, which are important to the economics of CSDRPs, it is desired that a majority of the solvent would be able to vaporize in the reservoir. Therefore, according to embodiments described herein, it is desired that near the end state of each cycle, and in particular during late cycles, lighter solvents would comprise the majority of the solvent mixture remaining in the reservoir, which can then be vaporized for recovery. Another option is to end the process by leaving a large volume of solvent in the reservoir, which is not highly valued, perhaps a low-value gas such as CO₂, N₂, SO₂, a non-condensable gas, an inert gas, or a combination thereof. Therefore, it may be desired that the solvent used throughout the early cycles is not the same as the solvent used in the late cycles. However, current CSDRPs do not teach solvent composition variation from cycle to cycle or within a cycle.

To help determine when to stop solvent injection in a given cycle or when to abandon a well altogether after several cycles of solvent injection and production, several recovery and efficiency measures may be used. One measure of oil recovery in a CDSRP is the volumetric oil rate. During an injection/production cycle, the volume of produced oil per unit time. During an injection/production cycle, the volume of produced oil should be above a minimum threshold to economically justify continuing operations. The volumetric oil rate may be used to decide when to terminate the production in a given cycle and initiate the solvent injection of the subsequent cycle. It may also be used to determine when to abandon the well altogether and move to a fresh reservoir region. One measure of the efficiency of a CSDRP is the ratio of produced oil volume to injected solvent volume during one complete injection/production cycle, called the OISR (produced Oil to Injected Solvent Ratio). This ratio alone or in conjunction with threshold volumetric oil rate may be used to decide when to terminate the production in a given cycle and initiate the solvent injection of the subsequent cycle. It may also be used to determine when to abandon the well altogether and move to a fresh reservoir region. The exact OISR threshold depends on the relative price of bitumen and solvent, among other factors. If either the rate or the OISR falls too low, the CSDRP is discontinued and any remaining solvent is then recovered by vaporization at a low abandonment pressure. Rather than abandon the well, another recovery process may be initiated. To maximize the economic return of a producing oil well it is desirable to maintain an economic oil rate and OISR as long as possible.

Prior descriptions of CSDRPs have not specified how to change the composition of the injected solvent as a function of time or volume injected or injection pressure in a given injection cycle or from cycle to cycle. Hence, there is a need for reliable methods to determine the solvent composition to be injected in a cycle and from cycle to cycle. These details of the cyclic process design are important to maximizing oil recovery while achieving efficient use of solvent and high solvent recovery, and are the subject of embodiments described herein.

To obtain a high OISR during a cycle, the solvent must contact and dissolve into oil/bitumen which has not been exposed to solvent in previous cycles and the oil-rich mixture must flow back to the well. Therefore, balancing solvent fingering, solvent solubility in bitumen, and viscosity reduction are important. Moreover, the production rate of oil is important, so maintaining a high permeability formation by limiting process created permeabilities impediments is important. Similarly, maintaining a low viscosity oil/solvent stream by ensuring the mixture is not too viscous because of a high viscosity injectant or because of an injectant that has a low solubility in the in-situ hydrocarbon, is also important. In addition, the need to recover a large fraction of the valuable injected solvent is important. Therefore, ensuring proper voidage replacement of the high value solvent with either a low value solvent or a low density solvent at the end of operation and even sometimes at the end of each cycle, is also important. Described herein are methods for injecting a fluid composition as a function of time, injection pressure, injection volume, and/or cycle to address one or more of the aforementioned challenges for CSDRP to achieve operational and/or economic benefit.

Conventional CSDRPs may address some of the aforementioned challenges in alternative ways, which may be less appealing depending on the scenario. To treat adverse fingering, conventional CSDRPs may limit the volume of solvent injected to limit how far fingers can grow or may inject a more viscous solvent blend which has a lower mobility contrast throughout the process. Inefficient utilization is also challenging in conventional CSDRPs where light solvents may phase separate and not efficiently contact the bitumen; this can result in rapid early production of high concentration solvent streams and long delayed production of high viscosity oil. Conventional CSDRPs do not have an effective method for mitigating early production of high solvent concentration other than to delay production after injection is complete to allow time for pressure and diffusion to better drive and mix the solvent with the bitumen. Introducing a long delay before production is not necessarily economically advantageous. To deal with the long period of high viscosity, low rate production, conventional CSDRPs may cut off the production and reinitiate injection, resulting in a large fraction of the bitumen, which has been contacted by solvent, remaining in the reservoir for multiple cycles. Also a reduced cycle length can delay the solvent production and therefore may be impractical to implement in a field application that is relying on re-injected solvent.

Overall, conventional CSDRPs preferably employ either a single solvent or a dominant solvent with additives, i.e. a solvent mixture. In previous descriptions of CSDRPs, changes in the composition of the solvent mixture as the cycles progress are not discussed, so the reader may assume it to be the same for all cycles or assume that changes in the mixture are not especially beneficial or deleterious. Prior CSDRPs fail to recognize the one drawback of using the same solvent for all cycles with changing reservoir conditions over the course of the process, and therefore fail to teach one skilled in the art the desire to change solvent composition over the process.

Prior CSDRPs also fail to teach one skilled in the art to how to overcome the recalcitrant effect of the formation of two (or more) liquid organic phases, resulting from the mixing of the solvent with bitumen. Typically a solvent-rich upper liquid phase and a bitumen-rich lower liquid phase with a higher viscosity and a higher density are formed. Being more viscous than the upper liquid phase, the lower liquid phase adversely affects the bitumen production rate by impeding flow through the reservoir, hindering flow through the wellbore completions, decreasing artificial lift performance and causing plugging issues in surface facilities that necessitate the use of heating or additional solvent at surface. Additionally, the accumulation of the viscous second phase in the near-well drainage radius may impede solvent recovery operations, for example, by hindering solvent vaporization in late cycle blowdown of the depleted reservoir.

Canadian Patent No. 2,349,234 to Lim et al. describes a CSDRP. The patent states (pg. 3, lines 32 & pg. 4 lines 1-5) that a solvent is a compound that has a liquid/vapor phase change pressure that is below the regularly used injection pressure of the reservoir and so is injected in the liquid phase. Preferably, the liquid/vapor phase change pressure should be close to the initial reservoir pressure and it should also be high enough so that the solvent vaporizes at the reduced pressures used for production. The patents do not specify how solvent composition should be varied within an injection cycle or from cycle to cycle. They also do not specify that a substantial fraction of the solvent injected in early cycles could be a solvent which does not vaporize when the reservoir pressure is reduced during production.

This patent to Lim et al. discusses the use of light hydrocarbons such as methane, ethane, propane, or a mixture thereof along with CO₂ as well as the use of C₄ to C₂₀ diluent (claims 3-6). While this patent allows for a large range of compositions to be injected in the CSDRP, including a combination of light and heavy hydrocarbons, there is no specific mention of designing the injected fluid composition to change within a cycle or from cycle to cycle in order to improve OSR, increase total solvent recovery, mitigate asphaltene precipitation near wellbore, achieve high solvent utilization efficiency, and/or mitigate adverse fingering. Moreover, this patent does not discuss varying the fraction of light and heavy solvents based on injection pressure, injection time, injection volume, cumulative produced volume, or cycle number.

Other documents describe cyclic solvent injection methods. Some of these other cyclic solvent methods are described below, but because they all rely on the injected solvent being in the vapor phase, none of the injection and production schemes discussed within them is particularly relevant to CSDRP. A vapor-phase solvent process operates by a fundamentally different process (diffusion) than CSDRP (liquid mixing), and embodiments discussed herein relate to overcoming challenges caused by liquid mixing to achieve more optimal performance.

Cyclic injection of a rich gas (e.g., natural gas with 20% propane) to enhance production of viscous, low-gas-content oils is described by Shelton et al. (“Cyclic Injection of Rich Gas Into Producing Wells to Increase Rates from Viscous-Oil Reservoirs”, SPE Paper 4375, 1973).

Cyclic injection of a heated aromatics-rich hydrocarbon vapor to enhance the in-situ recovery of viscous oil is described by P. R. Tabor in U.S. Pat. No. 4,362,213 (1982).

U.S. Pat. Nos. 5,899,274 (1999), 6,318,464 (2001), and 6,883,607 (2005) all describe various aspects and variations of cyclic and non-cyclic processes wherein light hydrocarbon (ethane, propane, or butane) vapor is used as an injectant to enhance heavy oil recovery. None of these patents claims specific strategies for determining injectant volumes or making decisions for switching from injection to production or vice versa.

Cyclic injection of a solvent mixture composed of a solvent which is a gas at the reservoir formation temperature and pressure and of a paraffinic C₆₊ solvent which is a liquid at the reservoir formation temperature and pressure is described in U.S. Pat. No. 3,954,141 (1976) by Allen et al. The solvent mixture is injected at a pressure where it is fully liquid and produced at a pressure where it is at least partially vaporized. U.S. Pat. No. 3,954,141 provides some guidance for solvent selection but does not discuss variation of solvent composition within a cycle or from cycle to cycle within the scope of the CSDRP, which does not incorporate a solvent mixture that is designed to be two-phase at reservoir conditions as U.S. Pat. No. 3,954,141 does.

Allen et al. (U.S. Pat. No. 4,007,785) disclose that viscous petroleum, including bitumen, may be recovered from viscous petroleum-containing formations, including tar sand deposits, by injecting into the formation a heated mixture of hydrocarbon solvents (Page 2, line 59). With regards to the sequence of injection of the mixture components, they disclose that the injection may be simultaneous (dependent claim number two) or sequential (dependent claim number three), but that the mixture should be injected all in one cycle. This patent to Allen et al. does not discuss altering the composition of the mixture as the cycles progress.

Lim et al (Canadian Patent No. 2,349,234) disclose a cyclic solvent process for in-situ bitumen and heavy oil production. They discuss the optimization of solvent mixing (page 14) and then claim (claim 5) a process wherein the viscosity of the solvent is modified by dissolving a viscous hydrocarbon liquid into it.

Coutee et al. (Canadian Patent Application No. 2,688,392) claim a process that uses (claim 21) a solvent that comprises ethane, propane, butane, pentane, carbon dioxide, or a combination thereof. They also describe a process wherein the injected fluid further comprises diesel, viscous oil, bitumen, or diluent, to provide flow assurance and wherein the injected fluid further comprises CO₂, natural gas, C₃₊ hydrocarbons, ketones, or alcohols.

Canadian Patent Application No. 2,645,267 to Chakrabarty discloses the use of a solvent for extracting bitumen, the solvent comprising: a) a polar component, the polar component being a compound comprising a non-terminal carbonyl group; and b) a non-polar component, the non-polar component being a substantially aliphatic substantially non-halogenated alkane; wherein the solvent has a Hansen hydrogen bonding parameter of 0.3 to 1.7.

Returning to embodiments of the present disclosure, described herein are processes for recovering viscous oil using a cyclic method where the solvent composition is varied over the course of the recovery process. For instance, earlier cycles can employ less vaporizing solvents (e.g. non-vaporizing hydrocarbons or organic solvents) and later cycles can employ more vaporizing solvents (e.g. vaporizing solvents such as light alkane hydrocarbons, N₂, and CO₂). In any given cycle, the solvent composition can also shift from non-vaporizing organic compounds or heavier hydrocarbons to lighter solvent compounds. Moreover, the composition between cycles or within any given cycle can also shift from solvent that is more miscible with the in-situ viscous oil to less miscible or from a solvent that has a lower asphaltene precipitation rate to a higher asphaltene precipitation rate, or from a solvent that has a higher aromatic content to a lower aromatic content. In the final cycles, a large fraction of the solvent in the reservoir should ideally be one which fully vaporizes at pressures above reservoir abandonment pressures. Alternatively, all highly valued solvents, such as hydrocarbon solvents may be largely replaced in the final cycles by lower-value solvents such as CO₂, N₂, SO₂, a non-condensable gas, an inert gas, or a combination thereof, such that a substantial amount of solvent can be left in the reservoir at the end of life without adversely impacting economics.

The non-vaporizing solvent should ideally be selected to be fully miscible with the native viscous oil such that there exists only one hydrocarbon phase during production. A preferred non-vaporizing solvent may be selected from aromatics (e.g. xylene, toluene), certain classes of ketones, diesel, diluent, synthetic crude oil, or other solvent which is non-vaporizing at reservoir abandonment conditions and forms one liquid phase with the native oil at production pressures and temperatures. For example, the first cycle may be mostly xylene with minor amounts of diesel or diluent. The next cycle may be mostly C₅-C₇ hydrocarbons, like diluent. The next few cycles may be lighter solvents which can be mostly vaporized in the reservoir, such as mostly propane. Final cycles may be pure light hydrocarbon which can vaporize or a lower value solvent such as carbon dioxide.

The injection of solvent may change the character of a fraction of the remaining oil. For example, after contact with diesel, some oil may be stripped of its heavier components. A subsequent cycle comprising mostly propane may be fully miscible with a fraction of the remaining oil because it has been stripped of its heavier components. The oil may ordinarily form two phases when contacted with propane, but because it has been previously contacted by diesel, it may only form one liquid phase when contacted by propane, providing flow assurance benefits.

One option is to use a solvent blend of at least two solvent components, a primary solvent and a secondary solvent. The initial ratio of primary to secondary solvent may be determined by lab tests of the target resource or by bitumen-solvent phase behavior models to minimize formation of a viscous second liquid phase. Simulation studies using a simulator capable of modeling four phase flow, may also be employed to limit the formation of a second hydrocarbon liquid phase. However, the ratio could be adjusted by injection well or pattern of injection wells with time as part of an optimized reservoir depletion plan to improve economic oil recovery in a cyclic solvent injection recovery process.

Depending on the availability and cost of the secondary solvent, it may be advantageous to balance the amount of secondary solvent vs. the degree of flow impairment such that gains in production rate justify the cost of the solvent. In particular, an expensive solvent blend could be used as a periodic stimulation fluid in a well operating primarily with a cost effective unblended solvent. The blend ratio could be adjusted to compensate for viscosity heterogeneity (perhaps due to biodegradation) according to well depth and stratigraphic variance of completed zones.

Within a cycle, variations in injected composition can also be used to improve mixing and mitigate adverse fingering. Depending on reservoir conditions, solvents with lower viscosity tend to finger more rapidly into the reservoir than those with higher viscosity. Therefore, it may be desirable to inject a higher viscosity solvent such as a diluent or xylene which will not finger as severely into the reservoir. In the same cycle, this can be followed up by the injection of a lighter solvent. This lighter solvent may therefore be injected into a lower viscosity mixture (e.g., a mixture of the high viscosity solvent and the in-situ bitumen), which will tend to mitigate the fingering of the lighter viscosity solvent since the effective mobility contrast has been reduced by the early injection of the heavier solvent. Moreover, this technique may serve to allow for longer production periods since it reduces the potential of forming two liquid phases as previously discussed, wherein one liquid phase is a heavy phase, which flows very slowly.

Another possible adjustment is reducing the secondary solvent concentration as reservoir depletion increases and well-to-well fluid communication becomes evident through reservoir surveillance. In a depleted reservoir, the flow impairment due to formation of the second liquid phase may be less detrimental because sufficient voidage has been created such that a sufficient flow path from the reservoir to the producing wells is maintained for the lower viscosity liquid phase. In the event of well-to-well communication, the formation of the second liquid phase may act to baffle the communication pathways through depleted reservoir and assist diversion of injected solvent to previously bypassed heavy oil. Similarly, deliberate targeted formation of a heavy second liquid phase may prevent unwanted communication pathways or thief zones to adjacent water or gas bearing zones.

Using more expensive solvents followed by less expensive solvents has economic benefit. All else being equal, solvents that are used earlier in the process will have higher recovery rates than solvents used later in the process. Therefore, it is advantageous to use the most expensive solvents first and gradually shift to cheaper solvents. In some locations non-vaporizing solvents tend to be more expensive than vaporizing solvents. Using a more expensive non-vaporizing solvent in early cycles may have an additional benefit of increasing the bitumen recovery rate since only one liquid phase is expected to be produced, which will have a relatively low viscosity compared to the viscosity of the heavy, second liquid phase formed when using a less expensive vaporizing solvent.

Solvent may also alternate periodically from heavy to light within a given cycle or from high solubility to low solubility or from highly aromatic to less aromatic or from less prone to asphaltene precipitation to more prone to asphaltene precipitation, particularly for early cycles.

An alternative mode would be to inject light hydrocarbon solvents and phase to heavy hydrocarbon solvents within a given cycle. This would enhance wellbore flow assurance, particularly during early production times in a given cycle since it would be expected that primarily a single phase would be near wellbore, reducing the impact of a high viscosity second liquid phase impeding production.

Another alternative mode would be to inject a solvent composition that is dependent upon the average reservoir temperature near the wellbore. For instance, when applying CSDRP as a follow-up recovery process to a thermal recovery process, the temperature near the wellbore may be well above reservoir temperature initially and may decline as a function of time and/or CSRDP cycle. One option would be to inject a higher fraction of heavier solvent in early cycles and gradually decrease the fraction of heavier solvent while increasing the fraction of lighter solvent in later cycles as the reservoir cools.

Embodiments Shown in FIGS. 2 to 6

According to one embodiment, as shown in FIG. 2, solvent composition is varied over early (202), mid (204), and late (206) cycles, starting at a high concentration of a heavy solvent and transitioning to a high concentration of a light hydrocarbon solvent, according to a disclosed embodiment.

FIG. 3 shows an alternative to FIG. 2 with solvent composition varying from cycle to cycle, starting at pure heavy solvent in cycle 1 (302), transitioning to pure light vaporizable solvent in cycle 3 (306). Cycle 2 (304) is mix of heavy and light solvent.

FIG. 4 is a cartoon schematic of the anticipated solvent fingering into the in-situ viscous oil (406 a and 406 b) in a given cycle for equivalent total solvent volumes injected of a pure low viscosity, light solvent (402 a) vs. that of a high viscosity, heavy solvent (404) followed by a low viscosity, light solvent (402 b).

FIG. 5 is a flow chart, according to an embodiment, for determining what solvent composition should be injected throughout a given cycle with decision points related to injection pressure, injection duration, and injection volume. In particular, using injection pressure as the threshold, one determines whether the injection pressure is greater than the threshold pressure (502 a). If yes, then the solvent to be injected is less than 10 vol. % of heavy solvent and more than 90 vol. % light solvent (504 a). If it is not (‘no’), then the solvent to be injected is more than 20 vol. % heavy solvent and less than 80% of light solvent (506 a). Similarly, using time as the threshold, one determines whether the injection time is greater than the threshold time (502 b). If yes, then the solvent to be injected is less than 10 vol. % of heavy solvent and more than 90 vol. % light solvent (504 b). If it is not (‘no’), then the solvent to be injected is more than 20 vol. % heavy solvent and less than 80% of light solvent (506 b). Similarly, using volume as the threshold, one determines whether the injection volume is greater than the threshold volume (502 c). If yes, then the solvent to be injected is less than 10 vol. % of heavy solvent and more than 90 vol. % light solvent (504 c). If it is not (‘no’), then the solvent to be injected is more than 20 vol. % heavy solvent and less than 80% of light solvent (506 c).

FIG. 6 is a flow chart, according to one embodiment, for determining what solvent composition should be injected for a given cycle with decision points related to cycle number. In particular, one determines whether the cycle number is smaller than an early cycle number threshold (602). If yes, then the solvent to be injected is greater than 20 vol. % of heavy solvent and less than 80 vol. % light solvent (604). If it is not (‘no’), then one determines whether the cycle number is greater than a late cycle threshold number (606). If yes, then the solvent to be injected is less than 10 vol. % of heavy solvent and more than 90 vol. % light solvent (608). If it is not (‘no’), then the solvent to be injected is more than 10 vol. % heavy solvent and more than 10 vol. % light solvent.

Modeled Example

Field results in a representative viscous oil field showed that xylene forms one liquid phase in the reservoir, whereas propane forms two liquid phases in the reservoir. A single cycle test in the same field showed that the production of two liquid phases may cause flow assurance problems, which were not encountered in the xylene test.

Computational models indicated that solvent recovery without vaporization is much lower than with vaporization of the solvent at the end of life. FIG. 7 shows the solvent storage ratio (the volumetric ratio of solvent remaining in the reservoir to oil produced) as a function of time over several cycles when operating with a single component fully miscible solvent above and below the solvent vaporization pressure. In FIG. 7, the solvent vaporization pressure is around 800 kPa, and it is clear that the amount of solvent remaining in the reservoir when producing at the last cycle below this vaporization pressure is substantially less than that when producing above the vaporization pressure, demonstrating the need for a majority of the solvent in the reservoir at the end of life to be a vaporizable solvent.

Experimental results demonstrated the solubility of heavy hydrocarbon and some organic solvents or a combination thereof in bitumen is high while the solubility of lighter hydrocarbon solvents is not as high. FIG. 8 is a table with the approximate solubilities of some hydrocarbon and non-hydrocarbon solvents in Cold Lake bitumen at 13° C. The vapor pressure, liquid density and viscosity of each solvent at 13° C. are also included.

From FIG. 9, which lists boiling points of certain solvents of interest, it is evident that at least a 10° C. temperature difference exists between the boiling points of each of the solvents listed in this table. For CO₂ (not shown in FIG. 9), however, at 1 atm, the minimum temperature at which 50 mass % of the composition of the total solvent is vapor is the sublimation temperature, which is approximately −57° C. at 1 atm.

In one embodiment, injection of a solvent mixture that produces a single hydrocarbon phase when mixed in any proportion with in-situ heavy oil may be desirable in early cycles. Laboratory results showed that a mixture of 30% acetone with 70% propane is such a solvent, which produced a single hydrocarbon phase with Cold Lake bitumen. Since acetone is a high value solvent with a lower vapor pressure than many light end alkane hydrocarbons, it may be desirable to transition to compositions that comprise less acetone as cycles progress until the injected composition contains no acetone in late cycles.

Details of the Laboratory Experiment are Given Below:

Acetone was added to propane in a 30:70 (by volume) ratio and the blend was injected to a 5.4 Darcy sand pack saturated with live Cold Lake bitumen. The lead-sand pack was subjected to a confining pressure of 7.5 MPa by pumping brine in the annulus between the lead sleeve and the stainless cylinder. The density of the produced fluid was continuously monitored to identify the existence of two liquid phases and determine the bitumen recovery based on the blend density, the bitumen density, solvent density and a blending model. The density of the produced fluid and the cumulative oil recovery as a function of pore volume solvent injected was measured. The density decreased with pore volume (PV) injected as the bitumen recovery increases. This decline is not a manifestation of the presence of two liquid phases. The absence of two liquid phases was further demonstrated by collecting two produced fluid samples under pressure: Sample 1 after injection into the core of 1.3 PV of solvent and Sample 2 after injection into the core of 2.3 PV of solvent. Each collected sample of solvent-bitumen mixture was then pumped through the densitometer and the density was recorded as a function of the percentage of the collected sample pumped through the densitometer. This confirmed Sample 1 was a fluid of roughly uniform density of 785±2 kg/m³ (FIG. 10) as was Sample 2 with roughly uniform density of 719±3 kg/m³ (FIG. 11). The difference in density between the two samples is due to higher concentration of solvent in Sample 1, which was collected at 1.3 PV solvent injected compared to Sample 2, which was collected at 2.3 PV solvent injected, as mentioned before.

The two figures show that this method eliminates (or at least significantly reduces) the presence of two liquid phases resulting in a fluid of uniform density. The example also shows that the absence of two liquid phases results in very good bitumen recovery: 66% of original oil in place at 1.3 PV and 98% OBIP at 2.3 PV.

Table 1 outlines the operating ranges for CSDRPs of some embodiments. The present invention is not intended to be limited by such operating ranges.

TABLE 1 Operating Ranges for a CSDRP, according to certain embodiments. Parameter Broader Embodiment Narrower Embodiment Injectant volume Fill-up estimated pattern pore Inject, beyond a pressure threshold, volume plus 2-15% of estimated 2-15% (or 3-8%) of estimated pore pattern pore volume; or inject, volume. beyond a pressure threshold, for a period of time (e.g. weeks to months); or inject, beyond a pressure threshold, 2-15% of estimated pore volume. Injectant Main solvent (>50 mass %) is C₂- Main solvent (>50 mass %) is C₂-C₁₂, composition, main C₂₀, diesel, diluent, ketones, diesel, or diluent and composition synthetic crude oil, heavy vacuum changes from heavier solvents to gas oil, alcohols, CO₂, aromatic lighter solvents within a cycle or hydrocarbons, or a combination between cycles. thereof. As described herein, alternative solvents may be used and the solvent composition is varied over time. Injectant Additional injectants may include C₆+, diluent, or diesel. composition, CO₂ (up to about 30 mass %), C₃₊, additive viscosifiers (e.g. diesel, viscous oil, bitumen, diluent), ketones, synthetic crude oils, heavy vacuum gas oils, alcohols, sulphur dioxide, nitrogen, hydrate inhibitors, steam, non- condensable gas, inert gas, polymer, biodegradable solid particles, salt, water soluble solid particles, or solvent soluble solid particles. Injectant phase & Solvent injected such that at the Solvent injected as a liquid, and most Injection pressure end of the injection cycle, greater solvent injected just under fracture than 25% by mass of the solvent pressure and above dilation pressure, exists as a liquid and less than P_(fracture) > P_(injection) > P_(dilation) > 50% by mass of the injectant P_(vaporP.) exists in the solid phase in the reservoir, with no constraint as to whether most solvent is injected above or below dilation pressure or fracture pressure. Injectant Enough heat to prevent hydrates Enough heat to prevent hydrates with temperature and locally enhance wellbore a safety margin, inflow consistent with Boberg- T_(hydrate) +5° C. to T_(hydrate) +50° C. Lantz mode Injection rate 0.1 to 10 m³/day per meter of 0.2 to 6 m³/day per meter of completed well length (rate completed well length (rate expressed expressed as volumes of liquid as volumes of liquid solvent at solvent at reservoir conditions reservoir conditions). Rates may also measured at a frequency of less be designed to allow for limited or than 1 day). controlled fracture extent, at fracture pressure or desired solvent conformance depending on reservoir properties. Threshold pressure Any pressure above initial A pressure between 60% and 100% (pressure at which reservoir pressure. of fracture pressure. injected solvent composition may be changed) Threshold time Within a cycle, less than 75% of Within a cycle, less than 20% of the (time at which the predicted duration of injection predicted duration of injection or over injected solvent or over the predicted well life, less the predicted well life, less than 50% composition may than 90% of the predicted life of of the predicted life of the field. be changed) the field. Threshold volume Within a cycle, the fill-up Within a cycle, the fill-up estimated (injected volume at estimated pattern pore volume pattern pore volume plus 1-2% of which injected plus 1-5% of estimated pattern estimated pattern pore volume or over solvent pore volume or over the predicted the predicted well life, less than 30% composition may well life, less than 90% of the total of the total volume of solvent injected. be changed) volume of solvent injected. Early cycle Any cycle after the first cycle but The third cycle. threshold # (early before the last predicted cycle cycle number at prior to well blowdown. which injected solvent composition may be changed) Late cycle Any cycle after the second cycle. One cycle before the last predicted threshold # (late cycle prior to well blowdown. cycle number at which injected solvent composition may be changed) Well length As long of a horizontal well as can 500 m-1500 m (commercial well). practically be drilled; or the entire pay thickness for vertical wells. Well configuration Horizontal wells parallel to each Horizontal wells parallel to each other, other, separated by some regular separated by some regular spacing of spacing of 60-600 m; Also 60-320 m. vertical wells, high angle slant wells & multi-lateral wells. Also infill injection and/or production wells (of any type above) targeting bypassed hydrocarbon from surveillance of pattern performance. Well orientation Orientated in any direction. Horizontal wells orientated perpendicular to (or with less than 30 degrees of variation) the direction of maximum horizontal in-situ stress. Minimum Generally, the range of the MPP A low pressure below the vapor producing pressure should be, on the low end, a pressure of the main solvent, (MPP) pressure significantly below the ensuring vaporization, or, in the vapor pressure, ensuring limited vaporization scheme, a high vaporization; and, on the high- pressure above the vapor pressure. end, a high pressure near the At 500 m depth with pure propane, 0.5 native reservoir pressure. For MPa (low)-1.5 MPa (high), values example, perhaps 0.1 MPa-5 that bound the 800 kPa vapor MPa, depending on depth and pressure of propane. mode of operation (all-liquid or limited vaporization). Oil rate Switch to injection when rate Switch when the instantaneous oil equals 2 to 50% of the max rate rate declines below the calendar day obtained during the cycle; oil rate (CDOR) (e.g. total oil/total Alternatively, switch when cycle length). Likely most absolute rate equals a pre-set economically optimal when the oil rate value. Alternatively, well is unable is at about 0.8 × CDOR. Alternatively, to sustain hydrocarbon flow switch to injection when rate equals (continuous or intermittent) by 20-40% of the max rate obtained primary production against during the cycle. backpressure of gathering system or well is “pumped off” and unable to sustain flow from artificial lift. Alternatively, well is out of sync with adjacent well cycles. Gas rate Switch to injection from production Switch to injection when gas rate when the producing gas rate exceeds the capacity of the pumping exceeds the capacity of the or gas venting system. During pumping or gas venting system. production, an optimal strategy is one Well is unable to sustain that limits gas production and hydrocarbon flow (continuous or maximizes liquid from a horizontal intermittent) by primary production well. against backpressure of gathering system with/or without compression facilities. Oil to Solvent Ratio Begin another cycle if the OISR of Begin another cycle if the OISR of the the just completed cycle is below just completed cycle is below 0.3. 0.5 or economic threshold. Abandonment Atmospheric or a value at which For propane and a depth of 500 m, pressure (pressure all of the solvent is vaporized. about 340 kPa, the likely lowest at which well is obtainable bottomhole pressure at the produced after operating depth and well below the CSDRP cycles are value at which all of the propane is completed) vaporized.

In Table 1, embodiments may be formed by combining two or more parameters and, for brevity and clarity, each of these combinations will not be individually listed.

In the context of this specification, diluent means a liquid compound that can be used to dilute the solvent and can be used to manipulate the viscosity of any resulting solvent-bitumen mixture. By such manipulation of the viscosity of the solvent-bitumen (and diluent) mixture, the invasion, mobility, and distribution of solvent in the reservoir can be controlled so as to increase viscous oil production.

The diluent is typically a viscous hydrocarbon liquid, especially a C₄ to C₂₀ hydrocarbon, or a mixture thereof, is commonly locally produced and is typically used to thin bitumen to pipeline specifications. Pentane, hexane, and heptane are common components of such diluents. Bitumen itself can be used to modify the viscosity of the injected fluid, often in conjunction with ethane solvent.

In certain embodiments, the diluent may have an average initial boiling point close to the boiling point of pentane (36° C.) or hexane (69° C.), though the average boiling point (defined further below) may change with reuse as the mix changes (some of the solvent originating from among the recovered viscous oil fractions). Preferably, more than 50% by weight of the diluent has an average boiling point lower than the boiling point of decane (174° C.). More preferably, more than 75% by weight, especially more than 80% by weight, and particularly more than 90% by weight of the diluent, has an average boiling point between the boiling point of pentane and the boiling point of decane. In further preferred embodiments, the diluent has an average boiling point close to the boiling point of hexane (69° C.) or heptane (98° C.), or even water (100° C.).

In additional embodiments, more than 50% by weight of the diluent (particularly more than 75% or 80% by weight and especially more than 90% by weight) has a boiling point between the boiling points of pentane and decane. In other embodiments, more than 50% by weight of the diluent has a boiling point between the boiling points of hexane (69° C.) and nonane (151° C.), particularly between the boiling points of heptane (98° C.) and octane (126° C.).

By average boiling point of the diluent, we mean the boiling point of the diluent remaining after half (by weight) of a starting amount of diluent has been boiled off as defined by ASTM D 2887 (1997), for example. The average boiling point can be determined by gas chromatographic methods or more tediously by distillation. Boiling points are defined as the boiling points at atmospheric pressure.

Uniform distribution of solvent to the reservoir during injection for a CSDRP is desirable to obtain good conformance in the reservoir and mobilize the entire resource along the wellbore. However, obtaining uniform distribution is challenged by phenomena such as viscous fingering, which may cause undesirable pressure distributions to form over the life of the reservoir. The location of such a differential injection or thief zone is difficult to predict, due to the inherent nature of the instabilities associated with the fingering process. This makes designing completions to achieve relatively uniform flow distribution difficult. Flow restricting devices, such as inflow control devices (ICD's) or limited entry perforations (LEP's), which provide a non-trivial pressure drop across the perforations, can be used to improve fluid conformance in solvent-based processes. A relatively uniform solvent distribution may be obtained by an optimal spacing and diameter of these perforations. In general, the completion design of a solvent-based process may entail estimating the range of uncertainties in injection pressure, permeability, and mobility in the near wellbore region due to fingering instabilities. Out of this analysis minimum threshold pressure drops may be determined through the perforated liner or completions which are necessary to obtain a relatively uniform distribution across the reservoir and mitigate the adverse fingering effects. Adjusting the injected fluid composition can assist in achieving the desired pressure drops. Heavier solvents will have less adverse viscous fingering effects than lighter solvents and will typically provide higher pressure drops during injection, thereby providing better conformance control.

In addition, injecting and producing from the same horizontal wellbore presents additional challenges to an optimal completion design. Typically, it would be desired that the pressure drop across the orifices during production would be minimal. Therefore, injecting heavier solvents in one period and transitioning to a lighter solvent in a subsequent period may assist in mitigating adverse fingering during injection and allow for larger orifices to be used in the completion. These larger orifices would assist in reducing the pressure drop across the orifices during production. Injecting a heavier solvent in an earlier period may also mitigate the formation of a heavy second liquid phase, mitigating the potential of a high viscosity, heavy second liquid phase fluid reaching the well during production, which may result in an undesirable large pressure drop across the completion.

Additional Embodiments

The first and subsequent periods may be separate cycles.

The first and subsequent periods may be within the same cycle. The first and subsequent periods may be separate and non-overlapping sets of cycles, wherein each set of cycles consists of consecutive cycles and comprises at least two cycles. The subsequent period may comprise a final cycle. The sets of cycles may comprise at least 3 cycles.

The 50 mass % vaporization temperature at 1 atm of the total composition of solvent injected over the first period, may be at least 20° C. higher, or at least 50° C. higher, than a 50 mass % vaporization temperature at 1 atm of the total composition of solvent injected over the subsequent period.

The solvent injected over the first period may be more miscible with the in-situ hydrocarbons than is the solvent injected over the subsequent period, in the underground reservoir.

The solvent injected over the first period may have a lower asphaltene precipitation rate in the in-situ hydrocarbons than the solvent injected over the subsequent period, when mixed with the in-situ hydrocarbons at an equivalent volumetric ratio at initial reservoir conditions.

The solvent injected over the first period may have a higher aromatic content than the solvent injected over the subsequent period.

The solvent injected over the first period may have a lower viscosity than the solvent injected over the subsequent period.

At least 90 mass % of the solvent injected over the subsequent period may be in a gaseous phase at reservoir conditions. The solvent injected over the subsequent period may comprise ethane, propane, butane, CO₂, natural gas, or a combination thereof. The solvent injected over the subsequent period may comprise SO₂, another non-condensable gas, another inert gas, or a combination thereof.

At least 90 mass % of the solvent injected over the first period may be in a liquid phase at reservoir conditions. The solvent injected over the first period may comprise an aromatic hydrocarbon, diesel, diluent, a ketone, a synthetic crude oil, a heavy vacuum gas oil, or a combination thereof.

The solvent injected over the first period may be at least 75% soluble with the in-situ hydrocarbons in the underground reservoir at initial reservoir pressure and temperature.

The solvent injected over the first period may be completely miscible with the in-situ hydrocarbons in the underground reservoir.

The solvent injected over the first period may be completely miscible with the in-situ hydrocarbons in the underground reservoir and the total composition of solvent injected over the subsequent period may form two liquid phases when mixed with in-situ hydrocarbons in at least one ratio.

The method may further comprise periodically injecting a periodic solvent, wherein a 50 mass % vaporization temperature at 1 atm of a total composition of periodic solvent injected over a periodic period, is at least 50° C. higher than a 50 mass % vaporization temperature at 1 atm of a total composition of solvent injected over an immediately preceding and an immediately subsequent solvent injection period, for limiting formation of a second liquid hydrocarbon phase.

The method may further comprise using second and third injection periods between the first and subsequent injection periods, wherein a 50 mass % vaporization temperature at 1 atm of a total composition of solvent injected over the first period, is at least 10° C. higher than a 50 mass % vaporization temperature at 1 atm of a total composition of solvent injected over the second period, wherein a 50 mass % vaporization temperature at 1 atm of a total composition of solvent injected over the second period, is at least 10° C. higher than a 50 mass % vaporization temperature at 1 atm of a total composition of solvent injected over the third period, and wherein a 50 mass % vaporization temperature at 1 atm of a total composition of solvent injected over the third period, is at least 10° C. higher than a 50 mass % vaporization temperature at 1 atm of a total composition of solvent injected over the subsequent period. The solvent injected over the first period may comprise at least 50 mass % of an aromatic hydrocarbon, diesel, diluent, a ketone, a synthetic crude oil, a heavy vacuum gas oil, or a combination thereof. The solvent injected over the second period may comprise at least 50 mass % of a C₅ to C₇ hydrocarbon, or a combination thereof. The solvent injected over the third period may comprise at least 50 mass % ethane, propane, butane, or a combination thereof. The solvent injected over the subsequent cycle may comprise at least 50 mass % CO₂, N₂, SO₂, another non-condensable gas, another inert gas, or a combination thereof. The solvent may comprise a blend of at least two solvent components, the ratio of which is changed between the first and subsequent periods to achieve the difference in the 50 mass % vaporization temperature between the first and subsequent cycles. The blend may comprise a) a polar component, the polar component being a compound comprising a non-terminal carbonyl group; and b) a non-polar component, the non-polar component being a substantially aliphatic substantially non-halogenated alkane. The polar component may comprise a ketone. The non-polar component may comprise a C₂-C₇ alkane. The polar component may comprise acetone and the non-polar component may comprises propane.

The injection well and the production well may utilize a common wellbore.

The in-situ hydrocarbons may be a viscous oil having a viscosity of at least 10 cP at initial reservoir conditions.

The injected fluid may comprise diesel, viscous oil, natural gas, bitumen, diluent, C₅₊ hydrocarbons, ketones, alcohols, non-condensable gas, water, biodegradable solid particles, salt, water-soluble solid particles, solvent-soluble solid particles, a viscous polymer solution, or a combination thereof.

The injected fluid may be heated such that it is injected into the underground reservoir at a temperature greater than 20° C.

At least 25 mass % of the solvent in an injection cycle may enter the reservoir as a liquid.

At least 25 mass % of the solvent at the end of an injection cycle may be a liquid.

An in-situ volume of fluid injected over a cycle may be equal to a net in-situ volume of fluids produced from the production well summed over all preceding cycles plus an additional in-situ volume of fluid. The additional in-situ volume of fluid may be, at reservoir conditions, equal to 2% to 15% of a pore volume within the reservoir zone around the injection well within which solvent fingers are expected to travel during the cycle.

The method may further comprise a first injection stage, wherein the solvent comprises a primary lighter solvent and a secondary heavier solvent; the proportion of which is selected based on the additional cost of the secondary heavier solvent versus the cost benefit realized by decreased flow impairment due to formation of a second liquid hydrocarbon phase resulting from the injection of the secondary heavier solvent, to optimize economic recovery of the in-situ hydrocarbons; wherein the primary solvent has a 50 mass % vaporization temperature at 1 atm of at least 20° C. lower than a 50 mass % vaporization temperature at 1 atm of the secondary solvent; a second injection stage, wherein the relative proportion of the primary lighter solvent is increased to account for the reduction in flow impairment caused by a second liquid hydrocarbon phase, resulting from increased reservoir voidage due to reservoir depletion; during the second injection stage, periodically injecting the secondary heavier solvent for limiting formation of a second liquid hydrocarbon phase; and a third injection stage, where the primary lighter solvent is injected to allow a second liquid hydrocarbon phase to form, for limiting adverse effects of well to well communication or reservoir thief zones, or both.

In the preceding description, for purposes of explanation, numerous details are set forth in order to provide a thorough understanding of the embodiments of the invention. However, it will be apparent to one skilled in the art that these specific details are not required in order to practice the invention.

The above-described embodiments of the invention are intended to be examples only. Alterations, modifications and variations can be effected to the particular embodiments by those of skill in the art without departing from the scope of the invention, which is defined solely by the claims appended hereto. 

1. A method of enhancing the effectiveness of a cyclic solvent injection and production process to aid recovery of in situ hydrocarbons from an underground reservoir, the method comprising: (a) injecting a volume of fluid comprising greater than 50 mass % of a viscosity reducing solvent into an injection well completed in the reservoir; (b) halting injection into the injection well and subsequently producing at least a fraction of the injected fluid and the in situ hydrocarbons from the reservoir through a production well; (c) halting production through the production well; and (d) subsequently repeating the cycle of steps (a) to (c); wherein a 50 mass % vaporization temperature at 1 atm of a total composition of solvent injected over a first period, is at least 10° C. higher than a 50 mass % vaporization temperature at 1 atm of a total composition of solvent injected over a subsequent period.
 2. The method of claim 1, wherein the first and subsequent periods are one of (i) separate cycles, (ii) within the same cycle and (iii) separate and non-overlapping sets of cycles, wherein each set of cycles consists of consecutive cycles and comprises at least two cycles. 3.-4. (canceled)
 5. The method of claim 1, wherein the subsequent period comprises a final cycle.
 6. The method of claim 1, wherein the sets of cycles comprises at least 3 cycles.
 7. The method of claim 1, wherein the 50 mass % vaporization temperature at 1 atm of the total composition of solvent injected over the first period, is one of (i) at least 20° C. higher than a 50 mass % vaporization temperature at 1 atm of the total composition of solvent injected over the subsequent period and (ii) at least 50° C. higher than a 50 mass % vaporization temperature at 1 atm of the total composition of solvent injected over the subsequent period.
 8. (canceled)
 9. The method of claim 1, wherein the solvent injected over the first period one of (i) is more miscible with the in situ hydrocarbons than is the solvent injected over the subsequent period, in the underground reservoir, (ii) has a lower asphaltene precipitation rate in the in situ hydrocarbons than the solvent injected over the subsequent period, when mixed with the in situ hydrocarbons at an equivalent volumetric ratio at initial reservoir conditions, (iii) has a higher aromatic content than the solvent injected over the subsequent period, and (iv) has a lower viscosity than the solvent injected over the subsequent period. 10.-12. (canceled)
 13. The method of claim 1, wherein at least 90 mass % of the solvent injected over one of (i) the subsequent period is in a gaseous phase at reservoir conditions and (ii) the first period is in a liquid phase at reservoir conditions.
 14. The method of claim 13, wherein the solvent injected over the subsequent period comprises one of (i) ethane, propane, butane, CO₂, natural gas, or a combination thereof and (ii) SO₂, another non-condensable gas, another inert gas, or a combination thereof. 15.-16. (canceled)
 17. The method of claim 16, wherein the solvent injected over the first period comprises an aromatic hydrocarbon, diesel, diluent, a ketone, a synthetic crude oil, a heavy vacuum gas oil, or a combination thereof.
 18. The method of claim 1, wherein the solvent injected over the first period is at least 75% soluble with the in situ hydrocarbons in the underground reservoir at initial reservoir pressure and temperature.
 19. The method of claim 1, wherein one of (i) the solvent injected over the first period is completely miscible with the in situ hydrocarbons in the underground reservoir and (ii) the solvent injected over the first period is completely miscible with the in situ hydrocarbons in the underground reservoir and the total composition of solvent injected over the subsequent period forms two liquid phases when mixed with in situ hydrocarbons in at least one ratio.
 20. (canceled)
 21. The method of claim 1, further comprising periodically injecting a periodic solvent, wherein a 50 mass % vaporization temperature at 1 atm of a total composition of periodic solvent injected over a periodic period, is at least 50° C. higher than a 50 mass vaporization temperature at 1 atm of a total composition of solvent injected over an immediately preceding and an immediately subsequent solvent injection period, for limiting formation of a second liquid hydrocarbon phase.
 22. The method of claim 1, further comprising using second and third injection periods between the first and subsequent injection periods, wherein a 50 mass % vaporization temperature at 1 atm of a total composition of solvent injected over the first period, is at least 10° C. higher than a 50 mass % vaporization temperature at 1 atm of a total composition of solvent injected over the second period, wherein a 50 mass % vaporization temperature at 1 atm of a total composition of solvent injected over the second period, is at least 10° C. higher than a 50 mass % vaporization temperature at 1 atm of a total composition of solvent injected over the third period, and wherein a 50 mass % vaporization temperature at 1 atm of a total composition of solvent injected over the third period, is at least 10° C. higher than a 50 mass % vaporization temperature at 1 atm of a total composition of solvent injected over the subsequent period.
 23. The method of claim 22, wherein the solvent injected over the first period comprises at least 50 mass % of an aromatic hydrocarbon, diesel, diluent, a ketone, a synthetic crude oil, a heavy vacuum gas oil, or a combination thereof; the solvent injected over the second period comprises at least 50 mass % of a C₅ to C₇ hydrocarbon, or a combination thereof; the solvent injected over the third period comprises at least 50 mass % ethane, propane, butane, or a combination thereof; and the solvent injected over the subsequent cycle comprises at least 50 mass % CO₂, N₂, SO₂, another non-condensable gas, another inert gas, or a combination thereof.
 24. The method of claim 1, wherein the solvent comprises a blend of at least two solvent components, the ratio of which is changed between the first and subsequent periods to achieve the difference in the 50 mass % vaporization temperature between the first and subsequent cycles.
 25. The method of claim 24, wherein the blend comprises a) a polar component, the polar component being a compound comprising a non-terminal carbonyl group; and b) a non-polar component, the non-polar component being a substantially aliphatic substantially non-halogenated alkane.
 26. The method of claim 24, wherein one of the polar component comprises a ketone and the non-polar component comprises a C₂-C₇ alkane.
 27. (canceled)
 28. The method of claim 25, wherein the polar component comprises acetone and the non-polar component comprises propane.
 29. The method of claim 1, wherein the injection well and the production well utilize a common wellbore.
 30. The method of claim 1, wherein the in situ hydrocarbons are a viscous oil having a viscosity of at least 10 cP at initial reservoir conditions.
 31. The method of claim 1, wherein the injected fluid comprises diesel, viscous oil, natural gas, bitumen, diluent, C₅₊ hydrocarbons, ketones, alcohols, non-condensable gas, water, biodegradable solid particles, salt, water soluble solid particles, solvent soluble solid particles, a viscous polymer solution, or a combination thereof.
 32. The method of claim 1, wherein the injected fluid is heated such that it is injected into the underground reservoir at a temperature greater than 20° C.
 33. The method of claim 1, wherein at least 25 mass % of the solvent one of in an injection cycle enters the reservoir as a liquid and at the end of an injection cycle is a liquid.
 34. (canceled)
 35. The method of claim 1, wherein an in situ volume of fluid injected over a cycle is equal to a net in situ volume of fluids produced from the production well summed over all preceding cycles plus an additional in situ volume of fluid.
 36. The method of claim 35, wherein the additional in situ volume of fluid is, at reservoir conditions, equal to 2% to 15% of a pore volume within the reservoir zone around the injection well within which solvent fingers are expected to travel during the cycle.
 37. The method of claim 1, wherein the method comprises: a first injection stage, wherein the solvent comprises a primary lighter solvent and a secondary heavier solvent; the proportion of which is selected based on the additional cost of the secondary heavier solvent versus the cost benefit realized by decreased flow impairment caused by the formation of a second liquid hydrocarbon phase resulting from the injection of the primary lighter solvent, to optimize economic recovery of the in situ hydrocarbons; wherein the primary solvent has a 50 mass % vaporization temperature at 1 atm of at least 20° C. lower than a 50 mass % vaporization temperature at 1 atm of the secondary solvent; a second injection stage, wherein the relative proportion of the primary lighter solvent is increased to account for the reduction in flow impairment caused by a second liquid hydrocarbon phase, resulting from increased reservoir voidage due to reservoir depletion; during the second injection stage, periodically injecting the secondary heavier solvent for limiting formation of a second liquid hydrocarbon phase; and a third injection stage, where the primary lighter solvent is injected to allow a second liquid hydrocarbon phase to form, for limiting adverse effects of well to well communication or reservoir thief zones, or both. 